In connection with the recovery of hydrocarbons from the earth, wellbores are generally drilled using a variety of different methods and equipment. According to one common method, a roller cone bit or fixed cutter bit is rotated against the subsurface formation to form the wellbore. The drill bit is rotated in the wellbore through the rotation of a drill string attached to the drill bit and/or by the rotary force imparted to the drill bit by a subsurface drilling motor powered by the flow of drilling fluid down the drill string and through downhole motor.
Frequently, as a well is being drilled, a string of coupled casing is run into the open-hole portion of the well bore and cemented in place by circulating cement slurry in the annulus between the exterior of the casing string and the wall of the wellbore. This is done by methods known in the art and for drilling purposes known in the art. Then the wellbore is drilled deeper. When drilling deeper, the rotating drill string is run through the interior of the casing string with the bit on the bottom of the drill string. The drill string comprises drill pipe joints joined together at tool joints (i.e. thread connections) and is rotated by the drilling rig at the surface. As the drill string is rotated the drill pipe, and more particularly the larger outside diameter portion of the tool joints may rub against the interior wall of the casing.
Rotating drill strings, like all moving mechanisms, exhibit friction that can result in mechanical wear of either or both the casing and the drill string. Friction and mechanical wear can cause drilling inefficiencies, due to increased power needed to overcome frictional resistance or due to maintenance or repair of assemblies due to wear.